Hydrocarbon fluids, such as oil and gas and or mixtures of these, are normally found in accumulations under pressure in the subsurface in porous formations. These hydrocarbons are obtained from the formations through the means of boring of wells that penetrates the strata that protects the formation.
In order to exploit such natural reservoirs of hydrocarbons, one or more bores are typically drilled in the ground from a position on the ground surface. Processing installations on or above the ground surface, which then in different ways are able to communicate with the reservoir, are further adapted to collect and treat the produced fluids.
Natural pressure in the reservoir acts to lift the produced fluids upward to the surface through a production tubing. The reservoir pressure must in this case exceed the hydrostatic pressure of the fluid in the well bore and back-pressure imposed by the production facilities at the surface for the well to produce naturally.
However, the natural pressure in a well will gradually decrease as the well is run, whereby this entail a smaller amount of produced fluids. This bring about a need to either increase the pressure in the fluid reservoir again, or in other ways to enhance the production of fluids. The basic idea for all such methods and/or devices is to drive more hydrocarbons out of the reservoir.
When an external source of energy is employed in the well, for example a pump, the well is said to produce by means of an artificial lifting. The two most common used systems today are however water injection and gas injection. The gas injection method is also known as pneumatic lifting or pneumatic pumping.
In common configuration utilised in this gas injection method, natural gas under high pressure is injected into the annular space between the casing and the production tubing. The gas injection devices, for instance valves, control subsequently the flow of gas that discharges from the annular space to the interior of the production tubing.
Depending on the properties of the well, one or more of gas injection valves are positioned at different locations along the length of the production tubing. When the pressurised gas enters the production tubing, it will expand and the consequential reduction in the density of the production flow will permit an increased flow of fluids.
There are known several different principles of operating a gas injection valve, one of this is based on the Venturi principles, for instance as described in WO 2004/092537 A1. Here a mandrel for a gas lift valve comprises an elongated member provided with means of connection at its ends. The body is provided with a side pocket and a side receptacle in the interior of which may be housed a gas lift valve that injects gas into the interior of the body of the mandrel by means of orifices positioned in a nose.
These gas injection valves may also, although their primary task is to be utilized as gas injectors, serve for chemical injection in the well. Furthermore, they may be produced in order to function as differential operating gas lift valves, shear open valves, dump/kill valves etc.
The purpose and specific approach of this invention is to provide a valve where the intention is to shear open the valve where the valve subsequently functions as a normal injection valve. The valve can also function as a dump/kill valve where the purpose of the valve is to shear open and thereafter be kept in this position.
Known in the art are valves for instance shown in GB 2.424.438 and U.S. Pat. No. 6,102,126.
GB 2.424.438 describes a valve for use in a downhole tool, where the valve has an inlet communicating with the work string from which it is anchored. The inlet provides a flow path of a first cross-sectional area. A sealing assembly comprising a spring biased seal cap moves within an outer tubular body to open and close a number of ports arranged through the body. The ports provide a flow path of a combined cross-sectional area greater than the first cross-sectional area and the valve is arranged such that the fluid flow through the inlet moves the seal cap to open the valve and create an unimpeded flow path between the inlet and the ports. These examples are utilizing pressure shear out systems but have experienced low efficiency reliability in respect of operation and shear out force. Therefore the need for a more reliable system and design has revealed the present invention.
GB 2.297.822 describes valves for use in inflatable packers in a well bore, and more particularly, to a system for utilizing a pressure limit valve with an inflatable packer or with closely coupled inflatable packers, for controlling pressure differentials to prevent malfunction of an inflatable packer in a well bore. The valve comprises a valve member, which normally seats on a seat and is spring biased to the closed position. A valve cap comprises a bore through which a valve stem can pass. The stem is held in the valve-shut position by a frangible pin. When a preset pressure in the bore is reached, the pin breaks permitting the valve to open and vent through the bore. After venting the spring shuts the valve and collets which are biased into contact with the stem contact an abutment preventing the valve from reopening.
U.S. Pat. No. 3,776,250 describes a valve collar for allowing a pipe string to fill up as it is lowered in a bore hole, while controlling the rate of fill up through a differential fill feature, utilizes a valve plunger in a valve body with the plunger opening against spring means and having an elastomeric collar intermediately occur above a predetermined differential pressure.
U.S. Pat. No. 3,407,830 describes gas lift valves for controlling the admission of gas or air into a column of fluid in a well to lift the column and to aid in flowing the fluid from the well.